Asphaltenes can be defined as the fraction of petroleum that is soluble in aromatics such as toluene and benzene and insoluble in paraffins such as hexane, heptane and decane. Better understanding of asphaltene concentration distributions in reservoirs would be helpful because of the huge dependence of crude oil viscosity on asphaltene content and the difficulties asphaltenes can present. Asphaltene precipitation and deposition in the oil field, which directly relate to asphaltene content in a hydrocarbon reservoir, are notorious for clogging subsurface formations, wells, flowlines, and surface facilities and can cause enormous disruption in oil production.
The current existing methods for in-situ measuring asphaltene content in producing reservoirs include downhole fluid analysis (DFA) in which measurements are made using optical filters that provide for identification of the color of the fluid in the reservoir. However, DFA focuses on the compositional analysis and is therefore of limited utility in determining the concentration distribution of asphaltenes.
Low-field NMR has been applied widely to well logging and the study of hydrocarbon samples in the petroleum industry. One-dimensional NMR (1D NMR), which usually measures transverse relaxation time, also referred to as spin-spin relaxation time, transverse relaxation time or T2, is limited in identification and quantitative evaluation of reservoir fluid components since the signals from different reservoir fluid components coexisting in local pores sometimes overlap each other in the T2 spectrum. This is particularly common in heavy oil reservoirs.
Improved in-situ quantification of asphaltene content in crude oils would be of significant benefit to the industry.